Water-based drilling fluid with cyclodextrin shale stabilizer

ABSTRACT

Well fluids and methods are provided that can be used for stabilizing a shale formation, especially during drilling of a well into or through a shale formation. The well fluids include: (i) a continuous water phase; (ii) a viscosity-increasing agent, wherein the viscosity-increasing agent comprises water-soluble hydrophilic polymer; (iii) a fluid loss control agent; and (iv) a cyclodextrin-based compound. The methods of drilling include the steps of: (A) introducing the well fluid into a zone of a subterranean formation; and (b) drilling the zone.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

TECHNICAL FIELD

The inventions are in the field of producing crude oil or natural gasfrom subterranean formations. More specifically, the inventionsgenerally relate to methods of drilling a well.

BACKGROUND

To produce oil or gas, a well is drilled into a subterranean formationthat is an oil or gas reservoir.

Drilling is the process of drilling the wellbore of a well. After aportion of the wellbore is drilled, sections of steel pipe, referred toas casing, which are slightly smaller in diameter than the borehole, areplaced and cemented in at least the uppermost portions of the wellbore.After drilling, the casing provides structural integrity to the newlydrilled borehole. The wellbore is then completed for production of oilor gas.

The well is created by drilling a hole into the earth (or seabed) with adrilling rig that rotates a drill string with a drilling bit attached tothe downward end. Usually the borehole is anywhere between about 5inches (13 cm) to about 36 inches (91 cm) in diameter. As upper portionsare cased or lined, progressively smaller drilling strings and bits mustbe used to pass through the uphole casings or liners, which steps theborehole down to progressively smaller diameters.

While drilling an oil or gas well, a drilling fluid is circulateddownhole through a drillpipe to a drill bit at the downhole end, outthrough the drill bit into the wellbore, and then back uphole to thesurface through the annular path between the tubular drillpipe and theborehole. The purpose of the drilling fluid is to lubricate the drillstring, maintain hydrostatic pressure in the wellbore, and carry rockcuttings out from the wellbore.

The drilling fluid can be water-based or oil-based. Oil-based fluidstend to have better lubricating properties than water-based fluids,nevertheless, other factors can mitigate in favor of using a water-baseddrilling fluid.

An example a water-based drilling fluid is a drilling mud, which caninclude an aqueous solution and undissolved solids (as solidsuspensions). A water-based drilling mud can be based on a brine. Thedissolved solids and the undissolved solids can be chosen to helpincrease the density of the drilling fluid. An example of an undissolvedweighting agent is barite (barium sulfate). The density of a drillingmud can be much higher than that of typical seawater or even higher thanhigh-density brines due to the presence of suspended solids.

In drilling, subterranean formations including clay can be encountered.Certain clays, such as montmorillonite, have the tendency to swell whenexposed to water, creating a potential drilling hazard when clay-bearingrock formations are exposed to water-based fluids during drilling. Suchclay is unstable and exposure to water in a drilling fluid can poseproblems such as hydration, solvation, and dispersion of the clay. Thisinstability of the clay can cause erosion and destroy the rockformation. The eroding of swelled clay particulate complicates downholedrilling fluid behavior. In addition, the swelling of clay particles inthe formation can reduce or plug the permeability of a reservoir rock.

SUMMARY OF THE INVENTION

Well fluids and methods are provided that can be used for stabilizing ashale formation during drilling of a well.

The well fluids include: (i) a continuous water phase; (ii) aviscosity-increasing agent, wherein the viscosity-increasing agentcomprises water-soluble hydrophilic polymer; (iii) a fluid loss controlagent; and (iv) a cyclodextrin-based compound.

The methods of drilling include the steps of: (A) introducing a wellfluid according to the invention into a zone of a subterraneanformation; and (b) drilling the zone.

In an embodiment, the zone penetrates or is in a subterranean formationof shale.

In another embodiment, the viscosity-increasing agent includes awater-soluble hydrophilic polymer.

These and other aspects of the invention and sub-combinations will beapparent to one skilled in the art upon reading the following detaileddescription. While the invention is susceptible to various modificationsand alternative forms, specific embodiments thereof will be described indetail and shown by way of example. It should be understood, however,that it is not intended to limit the invention to the particular formsdisclosed, but, on the contrary, the invention is to cover allmodifications and alternatives falling within the spirit and scope ofthe invention as expressed in the appended claims.

BRIEF DESCRIPTION OF THE DRAWING

The accompanying drawing is incorporated into the specification to helpillustrate examples according to the presently most-preferred embodimentof the invention. It should be understood that the figures of thedrawing are not necessarily to scale.

FIG. 1 illustrates the chemical structure of β cyclodextrin and itshydroxypropyl derivative.

DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST MODEDefinitions and Usages

Interpretation

The words or terms used herein have their plain, ordinary meaning in thefield of this disclosure, except to the extent explicitly and clearlydefined in this disclosure or unless the specific context otherwiserequires a different meaning.

If there is any conflict in the usages of a word or term in thisdisclosure and one or more patent(s) or other documents that may beincorporated by reference, the definitions that are consistent with thisspecification should be adopted.

The words “comprising,” “containing,” “including,” “having,” and allgrammatical variations thereof are intended to have an open,non-limiting meaning. For example, a composition comprising a componentdoes not exclude it from having additional components, an apparatuscomprising a part does not exclude it from having additional parts, anda method having a step does not exclude it having additional steps. Whensuch terms are used, the compositions, apparatuses, and methods that“consist essentially of” or “consist of” the specified components,parts, and steps are specifically included and disclosed.

The indefinite articles “a” or “an” mean one or more than one of thecomponent, part, or step that the article introduces.

Whenever a numerical range of degree or measurement with a lower limitand an upper limit is disclosed, any number and any range falling withinthe range is also intended to be specifically disclosed. For example,every range of values (in the form “from a to b,” or “from about a toabout b,” or “from about a to b,” “from approximately a to b,” and anysimilar expressions, where “a” and “b” represent numerical values ofdegree or measurement) is to be understood to set forth every number andrange encompassed within the broader range of values.

Oil and Gas Reservoirs

In the context of production from a well, however, oil and “gas” areunderstood to refer to crude oil and natural gas, respectively. Oil andgas are naturally occurring hydrocarbons in certain subterraneanformations.

A “subterranean formation” is a body of rock that has sufficientlydistinctive characteristics and is sufficiently continuous forgeologists to describe, map, and name it.

In geology, rock or stone is a naturally occurring solid aggregate ofminerals or mineraloids. The Earth's outer solid layer, the lithosphere,is made of rock. Three majors groups of rocks are defined: igneous,sedimentary, and metamorphic.

A subterranean formation having a sufficient porosity and permeabilityto store and transmit fluids is sometimes referred to as a “reservoir.”The vast majority of reservoir rocks are sedimentary rocks, but highlyfractured igneous and metamorphic rocks sometimes contain substantialreservoirs as well.

A subterranean formation containing oil or gas may be located under landor under the seabed off shore. Oil and gas reservoirs are typicallylocated in the range of a few hundred feet (shallow reservoirs) to a fewtens of thousands of feet (ultra-deep reservoirs) below the surface ofthe land or seabed.

Clay, Shale, and Shale Formations

The structural difference among clays (smectite, kaolinite, chlorite,illite) determines the surface area exposed to reservoir fluids orstimulating fluids. Generally, higher surface area indicates higherreactivity. However, not all the clay present in a rock is reactive.

Clays can be found in pore spaces, as part of the rock matrix, or asgrain-cementing material. Antigenic clays, which grow in the pores fromminerals in the connate water, can be pore-filling or pore-lining. Theseclays have considerable surface area exposed in the pore and can bereactive, while detrital clays that are part of the matrix are usuallyless reactive.

Shale is a fine-grained, fissile, detrital sedimentary rock formed byconsolidation of clay-sized and silt-sized particles into thin,relatively impermeable layers. Shale is formed from a mix of flakes ofclay minerals and tiny fragments (silt-sized particles) of otherminerals, especially quartz and calcite. The ratio of clay to otherminerals is variable. Detritus is a geological term used to describeparticles of rock derived from pre-existing rock through processes ofweathering and erosion. Detrital particles can consist of lithicfragments (particles of recognizable rock) or of monomineralic fragments(mineral grains). These particles are often transported throughsedimentary processes into depositional systems such as riverbeds, lakesor the ocean forming sedimentary successions. Shale is characterized bybreaks along thin laminae or parallel layering or bedding less than onecentimeter in thickness, called fissility.

A shale formation is a subterranean formation of shale. It is the mostabundant sedimentary rock.

Conventional Reservoirs

There are conventional and non-conventional types of reservoirs.

In a conventional reservoir, the hydrocarbons flow to the wellbore in amanner that can be characterized by flow through permeable media, wherethe permeability may or may not have been altered near the wellbore, orflow through permeable media to a permeable (conductive) bi-wingfracture placed in the formation. A conventional reservoir wouldtypically have a matrix permeability greater than about 1 milliDarcy(equivalent to about 1,000 microDarcy).

A conventional reservoir is usually in a shape that will traphydrocarbons and that is covered by a relatively impermeable rock, knownas cap rock. The cap rock forms a barrier above reservoir rock so thatfluids cannot migrate beyond the reservoir. A cap rock capable of beinga barrier to fluid migration on a geological time scale has apermeability that is less than about 1 microDarcy. Cap rock is commonlysalt, anhydrite, or shale.

In addition, the hydrocarbons located in the reservoir are locatedvertically based on their density where the movement of one of thereservoir fluid can apply a driving force to another reservoir fluid.Most conventional reservoir rocks are limestone, dolomite, sandstone, ora combination of these.

Non-Conventional Reservoirs

In a non-conventional reservoir, the permeability is less than 1milliDarcy. Non-conventional reservoirs include tight gas and shale.

Tight gas is natural gas that is difficult to access because the matrixpermeability is relatively low. Generally, tight gas is in asubterranean formation having a matrix permeability in the range ofabout 1 milliDarcy to about 0.01 milliDarcy (equivalent to about 10microDarcy). Conventionally, to produce tight gas it is necessary tofind a “sweet spot” where a large amount of gas is accessible, andsometimes to use various means to create a reduced pressure in the wellto help draw the gas out of the formation.

Shale, which is conventionally considered to be a cap rock, can includerelatively large amounts of organic material compared with other typesof rock. Gas is very difficult to produce from shale, however, becausethe matrix permeability of the shale is often less than about 1microDarcy.

Well Terms

A “well” includes a wellhead and at least one wellbore from the wellheadpenetrating the earth. The “wellhead” is the surface termination of awellbore, which surface may be on land or on a seabed. A “well site” isthe geographical location of a wellhead of a well. It may includerelated facilities, such as a tank battery, separators, compressorstations, heating or other equipment, and fluid pits. If offshore, awell site can include a platform.

The “wellbore” refers to the drilled hole, including any cased oruncased portions of the well or any other tubulars in the well. The“borehole” usually refers to the inside wellbore wall, that is, the rocksurface or wall that bounds the drilled hole. A wellbore can haveportions that are vertical, horizontal, or anything in between, and itcan have portions that are straight, curved, or branched. As usedherein, “uphole,” “downhole,” and similar terms are relative to thedirection of the wellhead, regardless of whether a wellbore portion isvertical or horizontal.

A wellbore can be used as a production or injection wellbore. Aproduction wellbore is used to produce hydrocarbons from the reservoir.An injection wellbore is used to inject a fluid, e.g., liquid water orsteam, to drive oil or gas to a production wellbore.

As used herein, introducing “into a well” means introducing at leastinto and through the wellhead. According to various techniques known inthe art, tubulars, equipment, tools, or well fluids can be directed fromthe wellhead into any desired portion of the wellbore.

As used herein, the word “tubular” means any kind of body in the generalform of a tube. Examples of tubulars include, but are not limited to, adrill pipe, a casing, a tubing string, a line pipe, and a transportationpipe. Tubulars can also be used to transport fluids such as oil, gas,water, liquefied methane, coolants, and heated fluids into or out of asubterranean formation. For example, a tubular can be placed undergroundto transport produced hydrocarbons or water from a subterraneanformation to another location.

As used herein, the term “annulus” means the space between two generallycylindrical objects, one inside the other. The objects can be concentricor eccentric. Without limitation, one of the objects can be a tubularand the other object can be an enclosed conduit. The enclosed conduitcan be a wellbore or borehole or it can be another tubular. Thefollowing are some non-limiting examples that illustrate some situationsin which an annulus can exist. Referring to an oil, gas, or water well,in an open hole well, the space between the outside of a tubing stringand the borehole of the wellbore is an annulus. In a cased hole, thespace between the outside of the casing and the borehole is an annulus.In addition, in a cased hole there may be an annulus between the outsidecylindrical portion of a tubular such as a production tubing string andthe inside cylindrical portion of the casing. An annulus can be a spacethrough which a fluid can flow or it can be filled with a material orobject that blocks fluid flow, such as a packing element. Unlessotherwise clear from the context, as used herein an annulus is a spacethrough which a fluid can flow.

As used herein, a “well fluid” broadly refers to any fluid adapted to beintroduced into a well for any purpose. A well fluid can be, forexample, a drilling fluid, a cementing composition, a treatment fluid,or a spacer fluid. If a well fluid is to be used in a relatively smallvolume, for example less than about 200 barrels (about 8,400 US gallonsor about 32 m³) it is sometimes referred to as a wash, dump, slug, orpill.

Drilling fluids, also known as drilling muds or simply “muds,” aretypically classified according to their base fluid, that is, the natureof the continuous phase. A water-based mud (“WBM”) has a water phase asthe continuous phase. The water can be brine. A brine-based drillingfluid is a water-based mud in which the aqueous component is brine. Insome cases, oil may be emulsified in a water-based drilling mud. Anoil-based mud (“OBM”) has an oil phase as the continuous phase. In somecases, a water phase is emulsified in the oil-based mud.

As used herein, the word “treatment” refers to any treatment forchanging a condition of a portion of a wellbore or an adjacentsubterranean formation; however, the word “treatment” does notnecessarily imply any particular treatment purpose. A treatment usuallyinvolves introducing a well fluid for the treatment, in which case itmay be referred to as a treatment fluid, into a well. As used herein, a“treatment fluid” is a fluid used in a treatment. The word “treatment”in the term “treatment fluid” does not necessarily imply any particulartreatment or action by the fluid.

A “zone” refers to an interval of rock along a wellbore that isdifferentiated from uphole and downhole zones based on hydrocarboncontent or other features, such as permeability, composition,perforations or other fluid communication with the wellbore, faults, orfractures. A zone of a wellbore that penetrates a hydrocarbon-bearingzone that is capable of producing hydrocarbon is referred to as a“production zone.” A “treatment zone” refers to an interval of rockalong a wellbore into which a well fluid is directed to flow from thewellbore. As used herein, “into a treatment zone” means into and throughthe wellhead and, additionally, through the wellbore and into thetreatment zone.

Generally, the greater the depth of the formation, the higher the statictemperature and pressure of the formation. Initially, the staticpressure equals the initial pressure in the formation before production.After production begins, the static pressure approaches the averagereservoir pressure.

A “design” refers to the estimate or measure of one or more parametersplanned or expected for a particular well fluid or stage of a wellservice. For example, a fluid can be designed to have components thatprovide a minimum viscosity for at least a specified time under expecteddownhole conditions. A well service may include design parameters suchas fluid volume to be pumped, required pumping time, or the shearconditions of the pumping.

The term “design temperature” refers to an estimate or measurement ofthe actual temperature at the downhole environment at the time of a welloperation. That is, design temperature takes into account not only thebottom hole static temperature (“BHST”) but also the effect of thetemperature of the well fluid on the BHST during the operation. Thedesign temperature is sometimes referred to as the bottom holecirculation temperature (“BHCT”) Because well fluids may be considerablycooler than BHST, the difference between the two temperatures can bequite large. Ultimately, if left undisturbed, a subterranean formationwill return to the BHST.

Substances, Chemicals, and Derivatives

A substance can be a pure chemical or a mixture of two or more differentchemicals.

A pure chemical is a sample of matter that cannot be separated intosimpler components without chemical change. A chemical element iscomposed of atoms with identical atomic number. A chemical compound isformed from different elements chemically combined in definiteproportions by mass.

An atom or molecule is the smallest particle of a chemical that retainsthe chemical properties of the element or compound. A molecule is two ormore chemically bound atoms with characteristic composition andstructure. Making or breaking bonds in a molecule changes it to adifferent chemical.

As used herein, “modified” or “derivative” means a compound or substanceformed by a chemical process from a parent compound or substance,wherein the chemical backbone skeleton of the parent polymer is retainedin the derivative. The chemical process preferably includes at most afew chemical reaction steps, and more preferably only one or twochemical reaction steps. As used herein, a “chemical reaction step” is achemical reaction between two chemical reactant species to produce atleast one chemically different species from the reactants (regardless ofthe number of transient chemical species that may be formed during thereaction) An example of a chemical step is a substitution reaction.Substitution on the reactive sites of a polymeric material may bepartial or complete.

Physical States and Phases

As used herein, “phase” is used to refer to a substance having achemical composition and physical state that is distinguishable from anadjacent phase of a substance having a different chemical composition ora different physical state.

As used herein, if not other otherwise specifically stated, the physicalstate or phase of a substance (or mixture of substances) and otherphysical properties are determined at a temperature of 77° F. (25° C.)and a pressure of 1 atmosphere (Standard Laboratory Conditions) withoutapplied shear.

Particle Terms

As used herein, a “particle” refers to a body having a finite mass andsufficient cohesion such that it can be considered as an entity buthaving relatively small dimensions. A particle can be of any sizeranging from molecular scale to macroscopic, depending on context.

A particle can be in any physical state. For example, a particle of asubstance in a solid state can be as small as a few molecules on thescale of nanometers up to a large particle on the scale of a fewmillimeters, such as large grains of sand. Similarly, a particle of asubstance in a liquid state can be as small as a few molecules on thescale of nanometers up to a large drop on the scale of a fewmillimeters. A particle of a substance in a gas state is a single atomor molecule that is separated from other atoms or molecules such thatintermolecular attractions have relatively little effect on theirrespective motions.

As used herein, “particulate” or “particulate material” refers to matterin the physical form of distinct particles in a solid or liquid state(which means such an association of a few atoms or molecules) unless thecontext otherwise requires. As used herein, a particulate is a groupingof particles having similar chemical composition and particle sizeranges anywhere in the range of about 0.5 micrometer (500 nm) e.g.,microscopic clay or silt particles, to about 3 millimeters, e.g., largegrains of sand).

A particulate can be of solid or liquid particles. As used herein,however, unless the context otherwise requires, “particulate” refers toa solid particulate. Of course, a solid particulate is a particulate ofparticles that are in the solid physical state, that is, the constituentatoms, ions, or molecules are sufficiently restricted in their relativemovement to result in a fixed shape for each of the particles.

It should be understood that the terms “particle” and “particulate,”includes all known shapes of particles including substantially rounded,spherical, oblong, ellipsoid, rod-like, fiber, polyhedral (such as cubicmaterials) etc., and mixtures thereof. For example, the term“particulate” as used herein is intended to include solid particleshaving the physical shape of platelets, shavings, flakes, ribbons, rods,strips, spheroids, toroids, pellets, tablets or any other physicalshape.

A particulate will have a particle size distribution (“PSD”) As usedherein, “the size” of a particulate can be determined by methods knownto persons skilled in the art.

One way to measure the approximate particle size distribution of a solidparticulate is with graded screens. A solid particulate material willpass through some specific mesh (that is, have a maximum size; largerpieces will not fit through this mesh) but will be retained by somespecific tighter mesh (that is, a minimum size; pieces smaller than thiswill pass through the mesh) This type of description establishes a rangeof particle sizes. A “+” before the mesh size indicates the particlesare retained by the sieve, while a “−” before the mesh size indicatesthe particles pass through the sieve. For example, −70/+140 means that90% or more of the particles will have mesh sizes between the twovalues.

Particulate materials are sometimes described by a single mesh size, forexample, 100 U.S. Standard mesh. If not otherwise stated, a reference toa single particle size refers to about the mid-point of theindustry-accepted mesh size range for the particulate.

The most commonly-used grade scale for classifying the diameters ofsediments in geology is the Udden-Wentworth scale. According to thisscale, a solid particulate having particles smaller than 2 mm indiameter is classified as sand, silt, or clay. “Sand” is a detritalgrain between 2 mm (equivalent to 2,000 micrometers) and 0.0625 mm(equivalent to 62.5 micrometers) in diameter. (Sand is also a termsometimes used to refer to quartz grains or for sandstone.) “Silt”refers to particulate between 74 micrometers (equivalent to about −200U.S. Standard mesh) and about 2 micrometers. “Clay” is a particulatesmaller than 3.9 micrometers.

Dispersions

A dispersion is a system in which particles of a substance of onechemical composition and physical state are dispersed in anothersubstance of a different chemical composition or physical state. Inaddition, phases can be nested. If a substance has more than one phase,the most external phase is referred to as the continuous phase of thesubstance as a whole, regardless of the number of different internalphases or nested phases.

A dispersion can be classified different ways, including, for example,based on the size of the dispersed particles, the uniformity or lack ofuniformity of the dispersion, and, if a fluid, whether or notprecipitation occurs.

A dispersion is considered to be heterogeneous if the dispersedparticles are not dissolved and are greater than about 1 nanometer insize. (For reference, the diameter of a molecule of toluene is about 1nm and a molecule of water is about 0.3 nm).

Heterogeneous dispersions can have gas, liquid, or solid as an externalphase. For example, in a case where the dispersed-phase particles areliquid in an external phase that is another liquid, this kind ofheterogeneous dispersion is more particularly referred to as anemulsion. A solid dispersed phase in a continuous liquid phase isreferred to as a sol, suspension, or slurry, partly depending on thesize of the dispersed solid particulate.

A dispersion is considered to be homogeneous if the dispersed particlesare dissolved in solution or the particles are less than about 1nanometer in size. Even if not dissolved, a dispersion is considered tobe homogeneous if the dispersed particles are less than about 1nanometer in size.

Heterogeneous dispersions can be further classified based on thedispersed particle size.

A heterogeneous dispersion is a “suspension” where the dispersedparticles are larger than about 50 micrometers. Such particles can beseen with a microscope, or if larger than about 50 micrometers (0.05 mm)with the unaided human eye. The dispersed particles of a suspension in aliquid external phase may eventually separate on standing, e.g., settlein cases where the particles have a higher density than the liquidphase. Suspensions having a liquid external phase are essentiallyunstable from a thermodynamic point of view; however, they can bekinetically stable over a long period depending on temperature and otherconditions.

A heterogeneous dispersion is a “colloid” where the dispersed particlesrange up to about 50 micrometer (50,000 nanometers) in size. Thedispersed particles of a colloid are so small that they settle extremelyslowly, if ever. In some cases, a colloid can be considered as ahomogeneous mixture. This is because the distinction between “dissolved”and “particulate” matter can be sometimes a matter of theoreticalapproach, which affects whether or not it is considered homogeneous orheterogeneous.

A solution is a special type of homogeneous mixture. A solution isconsidered homogeneous: (a) because the ratio of solute to solvent isthe same throughout the solution; and (b) because solute will neversettle out of solution, even under powerful centrifugation, which is dueto intermolecular attraction between the solvent and the solute. Anaqueous solution, for example, saltwater, is a homogenous solution inwhich water is the solvent and salt is the solute.

One may also refer to the solvated state, in which a solute ion ormolecule is complexed by solvent molecules. A chemical that is dissolvedin solution is in a solvated state. The solvated state is distinct fromdissolution and solubility. Dissolution is a kinetic process, and isquantified by its rate. Solubility quantifies the concentration of thesolute at which there is dynamic equilibrium between the rate ofdissolution and the rate of precipitation of the solute. Dissolution andsolubility can be dependent on temperature and pressure, and may bedependent on other factors, such as salinity or pH of an aqueous phase.

Solubility Terms

A substance is considered to be “soluble” in a liquid if at least 10grams of the substance can be dissolved in one liter of the liquid whentested at 77° F. and 1 atmosphere pressure for 2 hours and considered tobe “insoluble” if less soluble than this.

As will be appreciated by a person of skill in the art, thehydratability, dispersibility, or solubility of a substance in water canbe dependent on the salinity, pH, or other substances in the water.Accordingly, the salinity, pH, and additive selection of the water canbe modified to facilitate the hydratability, dispersibility, orsolubility of a substance in aqueous solution. To the extent notspecified, the hydratability, dispersibility, or solubility of asubstance in water is determined in deionized water, at neutral pH, andwithout any other additives.

Fluids

A fluid can be a single phase or a dispersion. In general, a fluid is anamorphous substance that is or has a continuous phase of particles thatare smaller than about 1 micrometer that tends to flow and to conform tothe outline of its container.

Examples of fluids are gases and liquids. A “gas” (in the sense of aphysical state) refers to an amorphous substance that has a hightendency to disperse (at the molecular level) and a relatively highcompressibility. A “liquid” refers to an amorphous substance that haslittle tendency to disperse (at the molecular level) and relatively highincompressibility. The tendency to disperse is related to IntermolecularForces (also known as van der Waal's Forces) (A continuous mass of aparticulate, e.g., a powder or sand, can tend to flow as a fluiddepending on many factors such as particle size distribution, particleshape distribution, the proportion and nature of any wetting liquid orother surface coating on the particles, and many other variables.Nevertheless, as used herein, a fluid does not refer to a continuousmass of particulate as the sizes of the solid particles of a mass of aparticulate are too large to be appreciably affected by the range ofIntermolecular Forces.)

As used herein, a fluid is a substance that behaves as a fluid underStandard Laboratory Conditions, that is, at 77° F. (25° C.) temperatureand 1 atmosphere pressure, and at the higher temperatures and pressuresusually occurring in subterranean formations without applied shear.

Every fluid inherently has at least a continuous phase. A fluid can havemore than one phase. The continuous phase of a well fluid is a liquidunder Standard Laboratory Conditions. For example, a well fluid can bein the form of be a suspension (solid particles dispersed in a liquidphase) an emulsion (liquid particles dispersed in another liquid phase)or a foam (a gas phase dispersed in a liquid phase).

As used herein, “water-based” means that water or an aqueous solution isthe dominant material of the continuous phase, that is, greater than 50%by weight, of the continuous phase of the fluid.

In contrast, “oil-based” means that oil is the dominant material byweight of the continuous phase of the fluid. In this context, the oil ofan oil-based fluid can be any oil.

In the context of a well fluid, oil is understood to refer to an oilliquid, whereas gas is understood to refer to a physical state of asubstance, in contrast to a liquid. In general, an oil is any substancethat is liquid under Standard Laboratory Conditions, is hydrophobic, andsoluble in organic solvents. Oils have a high carbon and hydrogencontent and are relatively non-polar substances, for example, having apolarity of 3 or less on the Snyder polarity index. This generaldefinition includes classes such as petrochemical oils, vegetable oils,and many organic solvents. All oils can be traced back to organicsources.

Apparent Viscosity of a Fluid

Viscosity is a measure of the resistance of a fluid to flow. In everydayterms, viscosity is “thickness” or “internal friction.” Thus, pure wateris “thin,” having a relatively low viscosity whereas honey is “thick,”having a relatively higher viscosity. Put simply, the less viscous thefluid is, the greater its ease of movement (fluidity). More precisely,viscosity is defined as the ratio of shear stress to shear rate.

A fluid moving along solid boundary will incur a shear stress on thatboundary. The no-slip condition dictates that the speed of the fluid atthe boundary (relative to the boundary) is zero, but at some distancefrom the boundary the flow speed must equal that of the fluid. Theregion between these two points is aptly named the boundary layer. Forall Newtonian fluids in laminar flow, the shear stress is proportionalto the strain rate in the fluid where the viscosity is the constant ofproportionality. However for non-Newtonian fluids, this is no longer thecase as for these fluids the viscosity is not constant. The shear stressis imparted onto the boundary as a result of this loss of velocity.

A Newtonian fluid (named after Isaac Newton) is a fluid for which stressversus strain rate curve is linear and passes through the origin. Theconstant of proportionality is known as the viscosity. Examples ofNewtonian fluids include water and most gases. Newton's law of viscosityis an approximation that holds for some substances but not others.

Non-Newtonian fluids exhibit a more complicated relationship betweenshear stress and velocity gradient (i.e., shear rate) than simplelinearity. Thus, there exist a number of forms of non-Newtonian fluids.Shear thickening fluids have an apparent viscosity that increases withincreasing the rate of shear. Shear thinning fluids have a viscositythat decreases with increasing rate of shear. Thixotropic fluids becomeless viscous over time at a constant shear rate. Rheopectic fluidsbecome more viscous over time at a constant sear rate. A Bingham plasticis a material that behaves as a solid at low stresses but flows as aviscous fluid at high stresses.

Most well fluids are non-Newtonian fluids. Accordingly, the apparentviscosity of a fluid applies only under a particular set of conditionsincluding shear stress versus shear rate, which must be specified orunderstood from the context. As used herein, a reference to viscosity isactually a reference to an apparent viscosity. Apparent viscosity iscommonly expressed in units of centipoise (“cP”).

Like other physical properties, the viscosity of a Newtonian fluid orthe apparent viscosity of a non-Newtonian fluid may be highly dependenton the physical conditions, primarily temperature and pressure.

Gels and Deformation

The physical state of a gel is formed by a network of interconnectedmolecules, such as a crosslinked polymer or a network of micelles. Thenetwork gives a gel phase its structure and an apparent yield point. Atthe molecular level, a gel is a dispersion in which both the network ofmolecules is continuous and the liquid is continuous. A gel is sometimesconsidered as a single phase.

Technically, a “gel” is a semi-solid, jelly-like physical state or phasethat can have properties ranging from soft and weak to hard and tough.Shearing stresses below a certain finite value fail to produce permanentdeformation. The minimum shear stress which will produce permanentdeformation is referred to as the shear strength or gel strength of thegel.

In the oil and gas industry, however, the term “gel” may be used torefer to any fluid having a viscosity-increasing agent, regardless ofwhether it is a viscous fluid or meets the technical definition for thephysical state of a gel. A “base gel” is a term used in the field for afluid that includes a viscosity-increasing agent, such as guar, but thatexcludes crosslinking agents. Typically, a base gel is mixed withanother fluid containing a crosslinker, wherein the mixture is adaptedto form a crosslinked gel. Similarly, a “crosslinked gel” may refer to asubstance having a viscosity-increasing agent that is crosslinked,regardless of whether it is a viscous fluid or meets the technicaldefinition for the physical state of a gel.

As used herein, a substance referred to as a “gel” is subsumed by theconcept of “fluid” if it is a pumpable fluid.

Viscosity and Gel Measurements

There are numerous ways of measuring and modeling viscous properties,and new developments continue to be made. The methods depend on the typeof fluid for which viscosity is being measured. A typical method forquality assurance or quality control (QA/QC) purposes uses a couettedevice, such as a FANN™ Model 35 or 50 viscometer or a CHANDLER™ model5550 HPHT viscometer, which measures viscosity as a function of time,temperature, and shear rate. The viscosity-measuring instrument can becalibrated using standard viscosity silicone oils or other standardviscosity fluids.

Due to the geometry of most common viscosity-measuring devices, however,solid particulate, especially if larger than silt (larger than 74micron) would interfere with the measurement on some types of measuringdevices. Therefore, the viscosity of a fluid containing such solidparticulate is usually inferred and estimated by measuring the viscosityof a test fluid that is similar to the fracturing fluid without anyproppant or gravel that would otherwise be included. However, assuspended particles (which can be solid, gel, liquid, or gaseousbubbles) usually affect the viscosity of a fluid, the actual viscosityof a suspension is usually somewhat different from that of thecontinuous phase.

Unless otherwise specified, the apparent viscosity of a fluid (excludingany suspended solid particulate larger than silt) is measured with aFann Model 50 type viscometer using an R1 rotor, B1 bob, and F1 torsionspring at a shear rate of 40 l/s, and at a temperature of 77° F. (25°C.) and a pressure of 1 atmosphere. For reference, the viscosity of purewater is about 1 cP.

A substance is considered to be a fluid if it has an apparent viscosityless than 5,000 cP (independent of any gel characteristic).

As used herein, a fluid is considered to be “viscous” if it has anapparent viscosity of 10 cP or higher. The viscosity of a viscous fluidis considered to break or be broken if the viscosity is greatly reduced.Preferably, although not necessarily for all applications depending onhow high the initial viscosity of the fluid, the viscous fluid breaks toa viscosity of 5 cP or lower.

Emulsions

An emulsion is a fluid including a dispersion of immiscible liquidparticles in an external liquid phase. In addition, the proportion ofthe external and internal phases is above the solubility of either inthe other. A chemical can be included to reduce the interfacial tensionbetween the two immiscible liquids to help with stability againstcoalescing of the internal liquid phase, in which case the chemical maybe referred to as a surfactant or more particularly as an emulsifier oremulsifying agent.

In the context of an emulsion, a “water phase” refers to a phase ofwater or an aqueous solution and an “oil phase” refers to a phase of anynon-polar, organic liquid that is immiscible with water, usually an oil.

An emulsion can be an oil-in-water (o/w) type or water-in-oil (w/o)type. A water-in-oil emulsion is sometimes referred to as an invertemulsion.

Biodegradability

“Biodegradable” means the process by which complex molecules are brokendown by micro-organisms to produce simpler compounds. Biodegradation canbe either aerobic (with oxygen) or anaerobic (without oxygen) Thepotential for biodegradation is commonly measured on well fluids ortheir components to ensure that they do not persist in the environment.A variety of tests exist to assess biodegradation.

As used herein, a substance is considered “biodegradable” if thesubstance passes a ready biodegradability test or an inherentbiodegradability test. It is preferred that a substance is first testedfor ready biodegradability, and only if the substance does not pass atleast one of the ready biodegradability tests then the substance istested for inherent biodegradability.

In accordance with Organisation for Economic Co-operation andDevelopment (OECD) guidelines, the following six tests permit thescreening of chemicals for ready biodegradability. As used herein, asubstance showing more than 60% biodegradability in 28 days according toany one of the six ready biodegradability tests is considered a passlevel for classifying it as “readily biodegradable,” and it may beassumed that the substance will undergo rapid and ultimate degradationin the environment. The six ready biodegradability tests are: (1) 301A:DOC Die-Away; (2) 301B: CO2 Evolution (Modified Sturm Test) (3) 301C:MITI (I) (Ministry of International Trade and Industry, Japan) (4) 301D:Closed Bottle; (5) 301E: Modified OECD Screening; and (6) 301F:Manometric Respirometry. The six ready biodegradability tests aredescribed below:

For the 301A test, a measured volume of inoculated mineral medium,containing 10 mg to 40 mg dissolved organic carbon per liter (DOC/l)from the substance as the nominal sole source of organic carbon, isaerated in the dark or diffuse light at 22±2° C. Degradation is followedby DOC analysis at frequent intervals over a 28-day period. The degreeof biodegradation is calculated by expressing the concentration of DOCremoved (corrected for that in the blank inoculum control) as apercentage of the concentration initially present. Primarybiodegradation may also be calculated from supplemental chemicalanalysis for parent compound made at the beginning and end ofincubation.

For the 301B test, a measured volume of inoculated mineral medium,containing 10 mg to 20 mg DOC or total organic carbon per liter from thesubstance as the nominal sole source of organic carbon is aerated by thepassage of carbon dioxide-free air at a controlled rate in the dark orin diffuse light. Degradation is followed over 28 days by determiningthe carbon dioxide produced. The CO₂ is trapped in barium or sodiumhydroxide and is measured by titration of the residual hydroxide or asinorganic carbon. The amount of carbon dioxide produced from the testsubstance (corrected for that derived from the blank inoculum) isexpressed as a percentage of ThCO₂. The degree of biodegradation mayalso be calculated from supplemental DOC analysis made at the beginningand end of incubation.

For the 301C test, the oxygen uptake by a stirred solution, orsuspension, of the substance in a mineral medium, inoculated withspecially grown, unadapted micro-organisms, is measured automaticallyover a period of 28 days in a darkened, enclosed respirometer at 25+/−1°C. Evolved carbon dioxide is absorbed by soda lime. Biodegradation isexpressed as the percentage oxygen uptake (corrected for blank uptake)of the theoretical uptake (ThOD) The percentage primary biodegradationis also calculated from supplemental specific chemical analysis made atthe beginning and end of incubation, and optionally ultimatebiodegradation by DOC analysis.

For the 301D test, a solution of the substance in mineral medium,usually at 2-5 milligrams per liter (mg/l) is inoculated with arelatively small number of micro-organisms from a mixed population andkept in completely full, closed bottles in the dark at constanttemperature. Degradation is followed by analysis of dissolved oxygenover a 28 day period. The amount of oxygen taken up by the microbialpopulation during biodegradation of the test substance, corrected foruptake by the blank inoculum run in parallel, is expressed as apercentage of ThOD or, less satisfactorily COD.

For the 301E test, a measured volume of mineral medium containing 10 to40 mg DOC/1 of the substance as the nominal sole source of organiccarbon is inoculated with 0.5 ml effluent per liter of medium. Themixture is aerated in the dark or diffused light at 22+2° C. Degradationis followed by DOC analysis at frequent intervals over a 28 day period.The degree of biodegradation is calculated by expressing theconcentration of DOC removed (corrected for that in the blank inoculumscontrol) as a percentage of the concentration initially present. Primarybiodegradation may also be calculated from supplemental chemicalanalysis for the parent compound made at the beginning and end ofincubation.

For the 301F test, a measured volume of inoculated mineral medium,containing 100 mg of the substance per liter giving at least 50 to 100mg ThOD/1 as the nominal sole source of organic carbon, is stirred in aclosed flask at a constant temperature (±1° C. or closer) for up to 28days. The consumption of oxygen is determined either by measuring thequantity of oxygen (produced electrolytically) required to maintainconstant gas volume in the respirometer flask or from the change involume or pressure (or a combination of the two) in the apparatus.Evolved carbon dioxide is absorbed in a solution of potassium hydroxideor another suitable absorbent. The amount of oxygen taken up by themicrobial population during biodegradation of the test substance(corrected for uptake by blank inoculum, run in parallel) is expressedas a percentage of ThOD or, less satisfactorily, COD. Optionally,primary biodegradation may also be calculated from supplemental specificchemical analysis made at the beginning and end of incubation, andultimate biodegradation by DOC analysis.

In accordance with OECD guidelines, the following three tests permit thetesting of chemicals for inherent biodegradability. As used herein, asubstance with a biodegradation or biodegradation rate of >20% isregarded as “inherently primary biodegradable.” A substance with abiodegradation or biodegradation rate of >70% is regarded as “inherentlyultimate biodegradable.” As used herein, a substance passes the inherentbiodegradability test if the substance is either regarded as inherentlyprimary biodegradable or inherently ultimate biodegradable when testedaccording to any one of three inherent biodegradability tests. The threetests are: (1) 302A: 1981 Modified SCAS Test; (2) 302B: 1992Zahn-Wellens Test; and (3) 302C: 1981 Modified MITI Test. “Inherentbiodegradability” refers to tests which allow prolonged exposure of thetest compound to microorganisms, a more favorable test compound tobiomass ratio, and chemical or other conditions which favorbiodegradation. The three inherent biodegradability tests are describedbelow:

For the 302A test, activated sludge from a sewage treatment plant isplaced in an aeration (SCAS) unit. The substance and settled domesticsewage are added, and the mixture is aerated for 23 hours. The aerationis then stopped, the sludge allowed to settle and the supernatant liquoris removed. The sludge remaining in the aeration chamber is then mixedwith a further aliquot of the substance and sewage and the cycle isrepeated. Biodegradation is established by determination of thedissolved organic carbon content of the supernatant liquor. This valueis compared with that found for the liquor obtained from a control tubedosed with settled sewage only.

For the 302B test, a mixture containing the substance, mineralnutrients, and a relatively large amount of activated sludge in aqueousmedium is agitated and aerated at 20° C. to 25° C. in the dark or indiffuse light for up to 28 days. A blank control, containing activatedsludge and mineral nutrients but no substance, is run in parallel. Thebiodegradation process is monitored by determination of DOC (or COD) infiltered samples taken at daily or other time intervals. The ratio ofeliminated DOC (or COD) corrected for the blank, after each timeinterval, to the initial DOC value is expressed as the percentagebiodegradation at the sampling time. The percentage biodegradation isplotted against time to give the biodegradation curve.

For the 302C test, an automated closed-system oxygen consumptionmeasuring apparatus (BOD-meter) is used. The substance to be tested isinoculated in the testing vessels with micro-organisms. During the testperiod, the biochemical oxygen demand is measured continuously by meansof a BOD-meter. Biodegradability is calculated on the basis of BOD andsupplemental chemical analysis, such as measurement of the dissolvedorganic carbon concentration, concentration of residual chemicals, etc.

General Measurement Terms

Unless otherwise specified or unless the context otherwise clearlyrequires, any ratio or percentage means by weight.

Unless otherwise specified or unless the context otherwise clearlyrequires, the phrase “by weight of the water” means the weight of thewater of the continuous phase of the fluid without the weight of anyviscosity-increasing agent, dissolved salt, suspended particulate, orother materials or additives that may be present in the water.

If there is any difference between U.S. or Imperial units, U.S. unitsare intended. For example, “gal/Mgal” means U.S. gallons per thousandU.S. gallons.

Unless otherwise specified, mesh sizes are in U.S. Standard Mesh.

General Description

Water-based drilling fluids provide various environmental advantagesover their invert (w/o) emulsion counterparts. However, shaleinstability is a big challenge while drilling with water-based muds(WBM). The shale instability leads to sloughing of shales, boreholecollapse, stuck-pipe, and disintegration of shale leading to increase infines. The increase in fines (solid particulate) can pose difficultiesin rheology control. In addition, it can increase the low gravity solidsconcentration in a downhole drilling fluid leading to reduced ROP (rateof penetration) All these issues tend to increase the drilling timethereby the cost. As used herein, a “shale stabilizer” is a chemicalsubstance that can be added to a drilling fluid to reduce shalesloughing.

Historically, either sodium chloride or potassium chloride salt has beenthe first choice to prevent shale instability. However these salts canadversely affect the eco-system by posing threat to the water as well asthe soil quality. In the absence of salts, shale stabilizers thus playimportant role in combating with the problematic reactive shaleformations.

Conventional shale stabilizers are provided as liquids. However, inaddition to potential environmental concerns regarding any chemicalsused in well operations such as drilling, problems such as solidifyingin cold conditions, transport, and spillage are normally associated withliquids.

This invention relates to shale stabilizers that help prevent shaleerosion with the use of a water based drilling fluid. The shalestabilizer of the invention is a cyclic oligosaccharide. Moreparticularly, the cyclic oligosaccharide is a cyclodextrin or aderivative of cyclodextrin. It has been discovered that cyclodextrinscan be used in a drilling fluid as an effective shale stabilizer.

Cyclodextrins are thermally very stable. For example, β-cyclodextrinbegins to degrade at a very high temperature of 572° F. Thus,cyclodextrins can be used in well fluids under high temperatureconditions.

Cyclodextrins are environmentally friendly, unlike most of the otherconventionally used shale stabilizers. For example, cyclodextrins andderivatives are being used in pharmaceutical and food industry and areconsidered non-toxic. They show low eco-toxicity and are readilybiodegradable.

In addition, a cyclodextrin, being a solid under Standard LaboratoryConditions, is free from the above mentioned problems associated withthe handling of liquids. Cyclodextrins can be used either in the form ofa solid or aqueous solution for making up a drilling fluid, as desiredor depending upon the need.

Drilling Fluids

The well fluids include: (i) a continuous water phase; (ii) aviscosity-increasing agent, wherein the viscosity-increasing agentcomprises water-soluble hydrophilic polymer; (iii) a fluid loss controlagent; and (iv) a cyclodextrin-based compound.

Continuous Water Phase

The drilling fluid is a water-based fluid. In some embodiments, thewater phase, including any dissolved materials therein, is present inthe drilling fluids in an amount in the range from about 50% to 100% byvolume of the drilling fluid.

Preferably, the water for use in the drilling fluid does not containanything that would adversely interact with the other components used inthe well fluid or with the subterranean formation.

The water phase can include freshwater or non-freshwater. Non-freshwatersources of water can include surface water ranging from brackish waterto seawater, brine, returned water (sometimes referred to as flowbackwater) from the delivery of a well fluid into a well, unused well fluid,and produced water. As used herein, “brine” refers to water having atleast 40,000 mg/L total dissolved solids.

Brines and other water sources may include those that comprisemonovalent, divalent, or trivalent cations. Some divalent or trivalentcations, such as magnesium, calcium, iron, and zirconium, may, in someconcentrations and at some pH levels, cause undesirable crosslinking ofa polymeric viscosity-increasing agent. Such crosslinking may beproblematic because, inter alia, it may cause filtration problems,injection problems, or causes regain permeability problems.

If a water source is used which contains such divalent or trivalentcations in concentrations sufficiently high to be problematic, then suchdivalent or trivalent salts may be removed, either by a process such asreverse osmosis, or by raising the pH of the water in order toprecipitate out such salts to lower the concentration of such salts inthe water before the water is used. Another method would be to include achelating agent to chemically bind the problematic ions to prevent theirundesirable interactions with the diutan. As used herein, the term“chelating agent” or “chelant” also refers to sequestering agents andthe like. Suitable chelants include, but are not limited to, citric acidor sodium citrate. Other chelating agents also are suitable.

Weighting Agents

In an embodiment, the water-based drilling fluid includes a weightingagent. Examples of weighting agents are water-soluble salts, especiallyinorganic salts. The weighting agent can be dissolved in the waterphase.

Salts may optionally be included in the drilling fluids for manypurposes. For example, salts may be added to a water source, forexample, to provide a brine, and a resulting drilling fluid, having adesired density. Salts may optionally be included for reasons related tocompatibility of the drilling fluid with the formation and formationfluids.

The method according to claim 1, wherein the weighting agent is in atleast a sufficient concentration such that the continuous water phasehas a density of at least 8.5 ppg. More preferably, the weighting agentis in at least a sufficient concentration such that the continuous waterphase has a density of at least 9 ppg. Most preferably, the weightingagent is in at least a sufficient concentration such that the continuouswater phase has a density in the range of about 10 ppg to 18 ppg.

The disposal of returned drilling fluid can be a problem, however,including because of the inclusion of high concentrations of alkalimetal halides such as KCl or NaCl, which are commonly used in drillingfluids. In an embodiment, the weighting agent comprises a water-solublesalt selected from the group consisting of: barium sulfate, hematite,calcium carbonate, and any combination thereof. Preferably, theweighting agent is barium sulfate. In an embodiment, however, thewater-based drilling fluid includes less than 10% of any combination ofdissolved alkali metal halide salts by weight of the water.

To determine whether a salt may be beneficially used for compatibilitypurposes, a compatibility test may be performed to identify potentialcompatibility problems. From such tests, one of ordinary skill in theart with the benefit of this disclosure will be able to determinewhether a salt should be included in a drilling fluid.

Viscosity-Increasing Agents

A well fluid can be adapted to be a carrier fluid for particulates. Forexample, during drilling, rock cuttings should be carried uphole by thedrilling fluid and flowed out of the wellbore. Rock cuttings can rangein size from silt-sized particles to chunks measured in centimeters. Therock cuttings typically have specific gravity greater than 2, which ismuch higher than that of many drilling fluids. These high-densitycuttings have a tendency to separate from water or oil very rapidly.

As many well fluids are water-based, partly for the purpose of helpingto suspend particulate of higher density, and for other reasons known inthe art, the density of the fluid used in a well can be increased byincluding highly water-soluble salts in the water. However, increasingthe density of a well fluid will rarely be sufficient to match thedensity of the particulate.

Increasing the viscosity of a well fluid can help prevent a particulatehaving a different specific gravity than a surrounding phase of thefluid from quickly separating out of the fluid.

A viscosity-increasing agent can be used to increase the ability of afluid to suspend and carry a particulate material in a well fluid. Aviscosity-increasing agent is sometimes referred to in the art as aviscosifying agent, viscosifier, thickener, gelling agent, or suspendingagent. In general, any of these refers to an agent that includes atleast the characteristic of increasing the viscosity of a fluid in whichit is dispersed or dissolved. There are several kinds ofviscosity-increasing agents or techniques for increasing the viscosityof a fluid.

Certain kinds of polymers can be used to increase the viscosity of afluid. In general, the purpose of using a polymer is to increase theability of the fluid to suspend and carry a particulate material.Polymers for increasing the viscosity of a fluid are preferably solublein the external phase of a fluid. Polymers for increasing the viscosityof a fluid can be naturally occurring polymers such as polysaccharides,derivatives of naturally occurring polymers, or synthetic polymers(e.g., polyacrylamide).

As used herein, a “polysaccharide” can broadly include a modified orderivative polysaccharide.

A polymer can be classified as being single chain or multi chain, basedon its solution structure in aqueous liquid media. Examples ofsingle-chain polysaccharides that are commonly used in the oilfieldindustry include guar, guar derivatives, and cellulose derivatives.Examples of multi-chain polysaccharides include xanthan, diutan, andscleroglucan, and derivatives of any of these.

Synthetic polymers and copolymers may be used. Examples of suchsynthetic polymers include, but are not limited to, polyacrylate,polymethacrylate, polyacrylamide, polyvinyl alcohol, andpolyvinylpyrrolidone.

The viscosity-increasing agent can be provided in any form that issuitable for the particular well fluid or application. For example, theviscosity-increasing agent can be provided as a liquid, gel, suspension,or solid additive that is admixed or incorporated into a well fluid.

The viscosity-increasing agent should be present in a well fluid in aform and in an amount at least sufficient to impart the desiredviscosity to a well fluid. If used, a viscosity-increasing agent may bepresent in the well fluids in a concentration in the range of from about0.01% to about 5% by weight of the water of the continuous water phase.

The viscosity of a fluid at a given concentration ofviscosity-increasing agent can be greatly increased by crosslinking theviscosity-increasing agent. A crosslinking agent, sometimes referred toas a crosslinker, can be used for this purpose. A crosslinker interactswith at least two polymer molecules to form a “crosslink” between them.

If crosslinked to a sufficient extent, the polysaccharide may form a gelwith water. Gel formation is based on a number of factors including theparticular polymer and concentration thereof, the particular crosslinkerand concentration thereof, the degree of crosslinking, temperature, anda variety of other factors known to those of ordinary skill in the art.

Cross-linking agents typically comprise at least one metal ion that iscapable of cross-linking the viscosity-increasing agent molecules.

Some crosslinking agents form substantially permanent crosslinks withviscosity-increasing polymer molecules. Such crosslinking agentsinclude, for example, crosslinking agents of at least one metal ion thatis capable of crosslinking gelling agent polymer molecules. Examples ofsuch crosslinking agents include, but are not limited to, zirconiumcompounds (such as, for example, zirconium lactate, zirconium lactatetriethanolamine, zirconium carbonate, zirconium acetylacetonate,zirconium maleate, zirconium citrate, zirconium oxychloride, andzirconium diisopropylamine lactate) titanium compounds (such as, forexample, titanium lactate, titanium maleate, titanium citrate, titaniumammonium lactate, titanium triethanolamine, and titaniumacetylacetonate) aluminum compounds (such as, for example, aluminumacetate, aluminum lactate, or aluminum citrate) antimony compounds;chromium compounds; iron compounds (such as, for example, iron chloride)copper compounds; zinc compounds; sodium aluminate; or a combinationthereof.

Sometimes, however, crosslinking is undesirable, as it may cause thepolymeric material to be more difficult to break and it may leave anundesirable residue in the formation.

Most, if not all, of the commonly used water-solubleviscosity-increasing agents are hydratable. As referred to herein,“hydratable” means capable of being hydrated by contacting thehydratable agent with water. Regarding a hydratable agent that includesa polymer, this means, among other things, to associate sites on thepolymer with water molecules and to unravel and extend the polymer chainin the water. Viscosity-increasing agents have been conventionallyhydrated directly in the water at the concentration to be used for thewell fluid.

A common problem with using hydratable agents is that many of thecommonly-used hydratable agents used for such purposes are sensitive todissolved ions in the water. The hydratable agents are often especiallysensitive to divalent cations such as calcium and magnesium. Forexample, divalent cations such as calcium and magnesium may inhibit andslow the time required for hydration of certain types of polymerscommonly used for such purposes.

In the context of hydratable polymers, water having total dissolvedsolids of more than 0.67 lb/gal (80 g/l) such that the density of thewater with the total dissolved solids is more than 9.0 lb/gal, isgenerally considered too high for many types of hydratable polymers.Some hydratable polymers may be sensitive to lower concentrations oftotal dissolved solids (“TDS”).

For example, xanthan gum, which is sometimes used as aviscosity-increasing agent, can be slow and difficult to hydratethoroughly in such aqueous solutions. Full hydration of the xanthanpolymer is important because incomplete hydration will impairdevelopment of viscosity in the fluid and may cause fine particulatematter of incompletely hydrated xanthan gum to damage the permeabilityof the formation. Hydration of xanthan in freshwater is not usuallyproblematic.

Furthermore, the hydratable polymer may be sensitive to other ions,including borate ions, which in some cases and under certain conditionscan undesirably crosslink the polymer.

It should be understood that merely increasing the viscosity of a fluidmay only slow the settling or separation of distinct phases and does notnecessarily stabilize the suspension of any particles in the fluid.

Certain viscosity-increasing agents can also help suspend a particulatematerial by increasing the elastic modulus of the fluid. The elasticmodulus is the measure of a substance's tendency to be deformednon-permanently when a force is applied to it. The elastic modulus of afluid, commonly referred to as G′, is a mathematical expression anddefined as the slope of a stress versus strain curve in the elasticdeformation region. G′ is expressed in units of pressure, for example,Pa (Pascal) or dyne/cm². As a point of reference, the elastic modulus ofwater is negligible and considered to be zero.

An example of a viscosity-increasing agent that is also capable ofincreasing the suspending capacity of a fluid is to use a viscoelasticsurfactant. As used herein, the term “viscoelastic surfactant” refers toa surfactant that imparts or is capable of imparting viscoelasticbehavior to a fluid due, at least in part, to the three-dimensionalassociation of surfactant molecules to form viscosifying micelles. Whenthe concentration of the viscoelastic surfactant in a viscoelastic fluidsignificantly exceeds a critical concentration, and in most cases in thepresence of an electrolyte, surfactant molecules aggregate into speciessuch as micelles, which can interact to form a network exhibitingelastic behavior.

As used herein, the term “micelle” is defined to include any structurethat minimizes the contact between the lyophobic (“solvent-repelling”)portion of a surfactant molecule and the solvent, for example, byaggregating the surfactant molecules into structures such as spheres,cylinders, or sheets, wherein the lyophobic portions are on the interiorof the aggregate structure and the lyophilic (“solvent-attracting”)portions are on the exterior of the structure.

These micelles may function, among other purposes, to stabilizeemulsions, break emulsions, stabilize a foam, change the wettability ofa surface, solubilize certain materials, or reduce surface tension. Whenused as a viscosity-increasing agent, the molecules (or ions) of thesurfactants used associate to form micelles of a certain micellarstructure (e.g., rod-like, wormlike, vesicles, etc., which are referredto herein as “viscosifying micelles”) that, under certain conditions(e.g., concentration, ionic strength of the fluid, etc.) are capable of,inter alia, imparting increased viscosity to a particular fluid orforming a gel. Certain viscosifying micelles may impart increasedviscosity to a fluid such that the fluid exhibits viscoelastic behavior(e.g., shear thinning properties) due, at least in part, to theassociation of the surfactant molecules contained therein.

As used herein, the term “surfactant gel” refers to fluids that exhibitor is capable of exhibiting viscoelastic behavior due, at least in part,to the association of surfactant molecules contained therein to formviscosifying micelles.

Viscoelastic surfactants may be cationic, anionic, or amphoteric innature. The viscoelastic surfactants can include any number of differentcompounds, including methyl ester sulfonates, hydrolyzed keratin,sulfosuccinates, taurates, amine oxides, ethoxylated amides, alkoxylatedfatty acids, alkoxylated alcohols (e.g., lauryl alcohol ethoxylate,ethoxylated nonyl phenol) ethoxylated fatty amines, ethoxylated alkylamines (e.g., cocoalkylamine ethoxylate) betaines, modified betaines,alkylamidobetaines (e.g., cocoamidopropyl betaine) quaternary ammoniumcompounds (e.g., trimethyltallowammonium chloride, trimethylcocoammoniumchloride) derivatives thereof, and combinations thereof.

In some treatment fluids, hydrophobically modified water-soluble polymerhas sometimes been used. This is less common in drilling fluids,however. As used herein, a “hydrophobically modified water-solublepolymer” is based on a polymer that without the hydrophobic modificationis or would be water soluble. As used herein, “hydrophobically modified”refers to the incorporation into the water-soluble (hydrophilic) polymerstructure of hydrophobic groups, wherein the alkyl chain length is fromabout 4 to about 22 carbons. Preferably, the hydrophobically modifiedwater-soluble polymer is water soluble.

The hydrophobically modified water-soluble polymers typically have amolecular weight in the range of from about 100,000 to about 10,000,000.In exemplary embodiments, the hydrophobically modified water-solublepolymers have a polymer backbone having polar heteroatoms. Generally,the polar heteroatoms present within a polymer backbone of thehydrophobically modified water-soluble polymer include, but are notlimited to, oxygen, nitrogen, sulfur, or phosphorous.

A hydrophobically-modified water-soluble polymer can have, for example,a plurality of hydrophobic groups attached to or within the backbone,wherein one or more of the hydrophobic groups includes a secondaryamine, or a tertiary amine, a tertiary phosphine, a quaternary amine, orany combination thereof.

Additional information regarding hydrophobically modified polymers isdisclosed, for example, in U.S. Pat. No. 7,563,750 issued Jul. 21, 2009,having for named inventors Larry S. Eoff, Eldon Dwyann Dalrymple, and B.Raghava Reddy, which is incorporated herein by reference in itsentirety.

In an embodiment of the invention, the viscosity-increasing agentcomprises or is a water-soluble hydrophilic polymer. A hydrophilicpolymer is water soluble. For example, the viscosity-increasing agentcan include a polymeric material selected from the group consisting of acellulosic, polyacrylic, or natural gum polymer.

In an embodiment of the present invention, however, theviscosity-increasing agent is not a viscoelastic surfactant. Forexample, in an embodiment the water-based drilling fluid has less than asufficient concentration of a viscoelastic surfactant to increase theviscosity of the water-based drilling fluid by more than 10 cP. Inanother embodiment, the water-based drilling fluid has less than 0.01%by weight of the water of any viscoelastic surfactant. In anotherembodiment, the water-based drilling fluid does not include aviscoelastic surfactant.

In an embodiment of the present invention, however, theviscosity-increasing agent is not hydrophobically modified. For example,in an embodiment the water-based drilling fluid has less than asufficient concentration of a hydrophobically-modified hydrophilicpolymer to increase the viscosity of the water-based drilling fluid bymore than 10 cP. In another embodiment, the water-based drilling fluidhas less than 0.01% by weight of the water of anyhydrophobically-modified hydrophilic polymer. In another embodiment, thewater-based drilling fluid does not include a hydrophobically-modifiedhydrophilic polymer

Fluid-Loss Control Agents

“Fluid loss” refers to the undesirable leakage of a fluid phase of anytype of well fluid into the permeable matrix of a zone. “Fluid-losscontrol” refers to additives or methods designed to reduce suchundesirable leakage. Providing effective fluid-loss control for wellfluids during certain stages of well operations is usually highlydesirable.

The usual approach to fluid-loss control is to substantially reduce thepermeability of the matrix of the zone with a fluid-loss controlmaterial that blocks the permeability at or near the face of the rockmatrix of the zone. For example, the fluid-loss control material may bea particulate that has a size selected to bridge and plug the porethroats of the matrix. All else being equal, the higher theconcentration of the appropriately sized particulate, the fasterbridging will occur. As the fluid phase carrying the fluid-loss controlmaterial leaks into the formation, the fluid-loss control materialbridges the pore throats of the matrix of the formation and builds up onthe surface of the borehole or fracture face or penetrates only a littleinto the matrix. The buildup of solid particulate or other fluid-losscontrol material on the walls of a wellbore or a fracture is referred toas a filter cake. Depending on the nature of a fluid phase and thefilter cake, such a filter cake may help block the further loss of afluid phase (referred to as a filtrate) into the subterranean formation.A fluid-loss control material is specifically designed to lower thevolume of a filtrate that passes through a filter medium.

Fluid-loss control materials are sometimes used in drilling fluids.Through a combination of viscosity, solids bridging, and cake buildup onthe porous rock, these pills oftentimes are able to substantially reducethe permeability of a zone of the subterranean formation to fluid loss.They also generally enhance filter-cake buildup on the face of theformation to inhibit fluid flow into the formation from the wellbore.

Fluid-loss control pills typically include an aqueous continuous phaseand a high concentration of a viscosifying agent (usually crosslinked).

Fluid-loss control agents can include, for example, a filter cakeforming material, sometimes also known as a filtration control agent(such as clay (e.g., bentonite) or an organic colloidal-sized solidparticulate (e.g., a biopolymer, cellulose polymer, or starch, modifiedstarch, polyanionic cellulose, plant tannin, a polyphosphate, a ligniticmaterial, a lignosulfonate, or a synthetic polymer), a filter cakebridging material (such as a calcium carbonate particulate, a celluloseparticulate, an asphalt particulate, and a gilsonite particulate), and alost circulation material to block larger openings in the formation(such as an appropriately-sized particulate of walnut shells, mica,xanthan, and modified cellulose). These and other materials are known inthe art as fluid-loss control agents.

In an embodiment, the fluid-loss control agent is in a concentration ofat least 1 ppg of the continuous water phase.

Crosslinked gels can also be used for fluid-loss control. Crosslinkingthe gelling agent polymer helps create a gel structure that can suspendsolids as well as provide fluid-loss control. Further, crosslinkedfluid-loss control pills have demonstrated that they require relativelylimited invasion of the formation face to be fully effective. Tocrosslink the viscosifying polymers, a suitable crosslinking agent thatincludes polyvalent metal ions is used. Boron, aluminum, titanium, andzirconium are common examples.

In an embodiment, the viscosity-increasing agent can help form afiltercake. In addition, a drilling fluid according to the inventionpreferably includes a filtrate control agent.

After application of a filter cake, it may be desirable to restorepermeability into the formation. If the formation permeability of thedesired producing zone is not restored, production levels from theformation can be significantly lower. Any filter cake or any solid orpolymer filtration into the matrix of the zone resulting from afluid-loss control application must be removed to restore theformation's permeability, preferably to at least its original level.This is often referred to as clean up.

The term “damage” as used herein refers to undesirable deposits in asubterranean formation that may reduce its permeability. Scale, skin,gel residue, and hydrates are contemplated by this term. Alsocontemplated by this term are geological deposits, such as, but notlimited to, carbonates or clay particulates located on the pore throatsof the sandstone in a subterranean formation.

After a well fluid is placed or used where desired in the well and forthe desired time, the fluid usually must be removed from the wellbore orthe formation to regain permeability for producing oil or gas from aformation.

Chemical breakers can be used to help remove a filtercake. No particularmechanism is necessarily implied by the term. Breakers must be selectedto meet the needs of each situation. First, it is important tounderstand the general performance criteria of breakers. In reducing theviscosity of the well fluid to a near water-thin state, the breaker mustmaintain a critical balance. Premature reduction of viscosity during thepumping or use of a well fluid can jeopardize the operation. Inadequatereduction of fluid viscosity after pumping can also reduce production ifthe required conductivity is not obtained.

For a polymeric viscosity-increasing agent, the breakers operate bycleaving the backbone of polymer by hydrolysis of acetyl group, cleavageof glycosidic bonds, oxidative/reductive cleavage, free radicalbreakage, or a combination of these processes.

Chemical breakers used to help remove a filtercake formed with such aviscosity-increasing agent are generally grouped into three classes:oxidizers, enzymes, and acids.

Cyclodextrin-Based Compound

As used herein, a “cyclodextrin-based compound” means a cyclodextrin ora derivative of cyclodextrin.

Cyclodextrins are a family of compounds made up of sugar moleculeschemically bonded together in a ring. More particularly, cyclodextrinsare cyclic oligosaccharide comprising at least 6 glucopyranose unitsjoined by α-(1,4) glycosidic linkages. Common cyclodextrins comprise 6to 8 glucopyranose units, where α-cyclodextrin has six glucopyranoseunits, β-cyclodextrin has seven glucopyranose units, and γ-cyclodextrinhas eight glucopyranose units. Cyclodextrins are produced from starch bymeans of enzymatic conversion. They are used in food, pharmaceutical,and chemical industries, as well as agriculture and environmentalengineering.

The term “derivative” in regard to a cyclodextrin means comprising anycyclodextrin as just defined in which at least one of the constituentglucose units is substituted, at least at one point, by a group or amolecule which can be of very diverse size and functionality, such as,for example, an alkyl or hydroxyalkyl group, and especially ahydroxypropyl group, or a mono- or disaccharide molecule such as amaltose, glucose, fructose or sucrose molecule. Examples of substituentgroups include methyl, acetyl, hydroxypropyl, or hydroxyethyl groups.Examples of cyclodextrin derivatives are methyl-α-cyclodextrin andhydroxypropyl-a-cyclodextrin, in particular methyl-a-cyclodextrin. Theterm “derivative” also encompasses cyclodextrin polymers obtained, forexample, by reaction of cyclodextrins with polyfunctional reactants.Examples of cyclodextrin derivatives are methyl-a-cyclodextrin andhydroxypropyl-a-cyclodextrin, in particular methyl-a-cyclodextrin.

In an embodiment of the invention, the shale stabilizer is acyclodextrin-based compound. In an embodiment the cyclodextrin has inthe range of 6 to 8 glucopyranose units. In an embodiment, the shalestabilizer is β-cyclodextrin or a derivative of β-cyclodextrin. In anembodiment, the shale stabilizer of the present invention isβ-cyclodextrin or hydroxypropyl-β-cyclodextrin. FIG. 1 illustrates thechemical structure of β cyclodextrin and its hydroxypropyl derivative.

As cyclodextrins result from renewable plant matter, namely amylaceousmatter, their biodegradability and their non-toxicity make them productswhich are entirely tolerated by the environment.

As cyclodextrin-based compounds are known to interact with hydrophobicgroups through hydrophobic interactions, in an embodiment the drillingfluid excludes other chemicals with such hydrophobic groups. U.S. Pat.No. 8,114,818. Without being limited by any theory, the cyclodextrinmodifier includes an internal cavity (see FIG. 1) that is believed to becapable of hosting a hydrophobic portion of a “guest” compound, such asof viscoelastic surfactant or a hydrophobically modified polymer. It isbelieved that such interaction or entrapment of the hydrophobic portionof a viscosifying agent would deactivate properties associated withhydrophobic associations that increase the viscosity of the fluid.Accordingly, the cyclodextrin-based compound may undesirably decreasethe viscosity of a drilling fluid for which a viscoelastic surfactant orhydrophobically-modified polymer contributes to the desired viscosity.

Similarly, because viscoelastic surfactants or hydrophobically-modifiedwater-soluble polymers might interact with and degrade the effectivenessof the cyclodextrin compound as a shale stabilizer, it is contemplatedin certain embodiments such surfactants or hydrophobically-modifiedwater-soluble polymers not be employed in the drilling fluid.

In an embodiment, the cyclodextrin-based compound does not substantiallyinteract with the viscosity-increasing agent. For example, in anembodiment, the cyclodextrin-based compound does not increase theviscosity of the water-based drilling fluid by more than 10 cP (relativeto an otherwise similar fluid without the cyclodextrin-based compound).In an embodiment, the cyclodextrin-based compound at least does notreduce the viscosity of the continuous water phase by more than 10 cP(relative to an otherwise similar fluid without the cyclodextrin-basedcompound).

pH and pH Adjuster

Preferably, the pH of the continuous aqueous phase of the drilling fluidis at least 7. More preferably, the pH of the drilling fluid is at least8. In an embodiment, the pH of the drilling fluid is at least 9.

In certain embodiments, the drilling fluids can include a pH-adjuster.Preferably, the pH adjuster does not have undesirable properties, asdiscussed above.

The pH-adjuster may be present in the drilling fluids in an amountsufficient to maintain or adjust the pH of the fluid. In someembodiments, the pH-adjuster may be present in an amount sufficient tomaintain or adjust the pH of the fluid to a desired pH.

In general, a pH-adjuster may function, inter alia, to affect thehydrolysis rate of the viscosity-increasing agent. In some embodiments,a pH-adjuster may be included in the drilling fluid, inter alia, toadjust the pH of the drilling fluid to, or maintain the pH of thedrilling fluid near, a pH that balances the duration of certainproperties of the drilling fluid (e.g. the ability to suspendparticulate).

In some embodiments, the pH-adjuster may comprise a small amount of abase such as MgO, NaOH, Na₂CO₃, Mg(OH)₂, and any combination thereof.The pH adjuster can be a buffer. In other embodiments, the pH-adjustermay be any other substance known in the art capable of maintaining thepH of the breaker in a limited range. One of ordinary skill in the art,with the benefit of this disclosure, will recognize the appropriatepH-adjuster and amount thereof to use for a chosen application.

Other Additives

The method according to claim 1, wherein the water-based drilling fluidadditionally comprises one or more additives selected from the groupconsisting of: a surfactant (such foamer, defoamer, wetting agent,detergent, lubricant, and corrosion inhibitor), a water softener (suchas sodium carbonate), an oxygen scavenger, a biocide, and a corrosioninhibitor (other than surfactant).

Drilling Fluid as O/W Emulsion

If desired, the drilling fluids may be used in the form of anoil-in-water emulsion. An example of a suitable emulsion would comprisean aqueous continuous phase and a suitable hydrocarbon as another phase.In some embodiments, the emulsion may comprise approximately 70% of anaqueous continuous phase and 30% of a suitable hydrocarbon. Otherbenefits and advantages to using emulsions for certain well fluids andmethods will be evident to one of ordinary skill in the art.

Method of Drilling a Zone with the Drilling Fluid

According to an embodiment of the invention, a method of drilling a wellis provided, the method including the steps of: forming a drilling fluidaccording to the invention; and drilling in the well. In an embodiment,the drilling zone penetrates or is in a subterranean formation of shale.

A well fluid can be prepared at the job site, prepared at a plant orfacility prior to use, or certain components of the well fluid can bepre-mixed prior to use and then transported to the job site. Certaincomponents of the well fluid may be provided as a “dry mix” to becombined with fluid or other components prior to or during introducingthe well fluid into the well.

In certain embodiments, the preparation of a well fluid can be done atthe job site in a method characterized as being performed “on the fly.”The term “on-the-fly” is used herein to include methods of combining twoor more components wherein a flowing stream of one element iscontinuously introduced into flowing stream of another component so thatthe streams are combined and mixed while continuing to flow as a singlestream as part of the on-going drilling. Such mixing can also bedescribed as “real-time” mixing.

In an embodiment, the step of delivering a well fluid into a well iswithin a relatively short period after forming the well fluid, e.g.,less within 30 minutes to one hour. More preferably, the step ofdelivering the well fluid is immediately after the step of forming thewell fluid, which is “on the fly.” It should be understood that the stepof delivering a well fluid into a well can advantageously include theuse of one or more fluid pumps.

In an embodiment, the step of introducing comprises introducing underconditions for drilling the zone. The step of introducing can be at thesame time or as part of the step of drilling. In an embodiment, the stepof introducing is at a rate and pressure below the fracture pressure ofthe zone.

In an embodiment, the step of drilling is in a zone that penetrates oris in a subterranean formation of shale.

Preferably, after drilling, a step of producing hydrocarbon from thesubterranean formation is the desirable objective.

EXAMPLES

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the invention.

To test for the effectiveness of a cyclodextrin as a shale stabilizer,shale recovery tests and fluid rheology tests were performed on 11 poundper US gallon (“ppg”) water-based drilling fluids.

In general, a shale sample was initially kept overnight in an oven at105° C. for drying. The dried shale was then crushed in a pestle-mortarand screened to obtain shale cuttings that pass through a 5 US meshscreen, but are retained on a 10 US mesh screen. The graded shalecuttings (30 grams) were placed into drilling fluid samples inpint-sized jars. The drilling fluids along with the cuttings in the pintjars were hot rolled at 150° F. and 20 revolutions per minute (rpm) for16 hours. After completion of the rolling, the cuttings were againscreened through a 10-mesh screen. The cuttings retained on the 10 meshscreen are then washed with 5% KCl solution, subsequently with water,then dried at 105° C., and finally weighed. The test results areprovided as percent recovery of the shale.

The shale recovery testing was performed using a sample of London clayoutcrop cuttings. The X-ray diffraction (“XRD”) composition of the clayis provided in Table 1.

TABLE 1 Composition of the London Clay Sample London clay Quartz, wt %26.00 Smectite, wt % 20.00 Illite, wt % 49.00 Kaolin, wt % 1.00Chlorite, wt % 2.00

A typical water-based drilling fluid was formed as “base” fluid for thetesting. The base fluid was an 11 ppg water-based drilling fluid wasformulated with water, a viscosity-increasing agent (a water-solublehydrophilic polymer, specifically, xanthan), a weighting agent (barite,also known as barium sulfate), a filtration control agent, and a pHadjuster. In some embodiments, the drilling fluid does not includeinorganic halide salts (e.g., NaCl or KCl), which can cause problems incertain kinds of subterranean formations.

The viscosity-increasing agent used in the base fluid was BARAZAN D™xanthan gum powder, which is commercially available from BaroidIndustrial Drilling Products of Halliburton Energy Services, Inc.

The fluid-loss control agents used were a polyanionic cellulose and amodified starch, which types of products are commercially available fromBaroid Industrial Drilling Products of Halliburton Energy Services, Inc.

In a preferred embodiment of a water-based drilling fluid, a polyanioniccellulose is used as a fluid-loss control agent, which can also providesecondary viscosity, is effective at low concentrations, is suitable foruse in fresh water, salt water, and brine-based fluids, is stable up to300° F. (149° C.), is non-toxic, and does not require the use of abiocide.

In a preferred embodiment of a water-based drilling fluid, a modifiedstarch is used as an additional fluid-loss control agent to reduce mudfiltrate in most water-based fluid systems. Such a modified starch canbe made to be functional in freshwater through saturated saltenvironments and does not increase fluid viscosity, is temperaturestable to approximately 250° F. (121° C.).

The weighting agent used in the base fluid was barite, which is alsoknown as barium sulfate. Barite is commonly used to weight drillingmuds. Typically, 85% to 90% of the barite additive (as a solidparticulate before dissolving) will pass through a 325 US mesh sieve.Barite additive is effective at bottom hole temperatures (BHTs) up toabout 500° F. (260° C.) A barite additive concentration of 135 lb/sackof cement will provide a maximum slurry weight of 19 lb/gal. Bariteadditive can increase slurry density to help restrain high formationpressures and improve mud displacement, has application in deep,high-temperature wells, and the US Environmental Protection Agency (EPA)does not classify barite additive as a hazardous waste.

The pH control agent used was BARABUF™, commercially available fromBaroid Industrial Drilling Products of Halliburton Energy Services, Inc.BARABUF™ pH buffer is a fine powder of 98% magnesium oxide (MgO) It isused to provide alkalinity for all water based systems and is compatiblewith freshwater, brines, and brine polymer systems. BARABUF™ pH bufferwill dissolve in water and raise the pH of an aqueous system to 10.3. AtpH 10.3, no more BARABUF™ pH buffer will dissolve. The remainingundissolved product will dissolve if the pH starts to fall and therebyact as a pH buffer. BARABUF™ pH buffer can be safer to use than causticsoda.

The particular formulation of the base fluid is provided in Table 2. The% shale recovery obtained for this 11 ppg “base” base fluid was 33%.

Water-based drilling fluids that were similar to the base fluid werethen formulated with a few conventionally employed shale stabilizers.The particular formulations are provided as drilling fluids 1, 2, and 3in Table 2. The percent recovery of London Clay obtained for fluids withthese conventionally employed shale stabilizers was 86.2%, 72.4% and84.2% respectively.

In addition, water-based drilling fluids that were similar to the basefluid were then formulated with β-cyclodextrin (at two differentconcentrations) and hydroxypropyl β-cyclodextrin. The particularformulations are provided as drilling fluids 4, 5, and 6 in Table 2. Thepercent recovery of London Clay for the three fluids formulated withβ-cyclodextrin and hydroxypropyl β-cyclodextrin was 84%, 88.4%, and 88%.

These results show that the cyclodextrin and its derivative helped inachieving the shale stability in a very reactive London Clay and itsperformance as a shale stabilizer was comparable to that of theconventional shale stabilizers.

TABLE 2 Shale Recovery for Drilling Fluids Hot Rolled with London ClaySample Drilling Fluid Base 1 2 3 4 5 6 Water (lb) 313 306.55 310 297.5310 307 310 NaCl (lb) 0 0 0 0 0 0 0 Xanthan gum (lb) 0.65 0.65 0.65 0.650.65 0.65 0.65 Polyanionic cellulose 1 1 1 1 1 1 1 fluid-loss controlagent (lb) Modified starch 2 2 2 2 2 2 2 fluid-loss control agent (lb)Conventional — 7 — — — — — shale inhibitor #1 (lb) Conventional — — 3.5— — — — shale inhibitor #2 (lb) Conventional — — — 15 — — — shaleinhibitor #3 (lb) β-Cyclodextrin (lb) — — — — 3 6 — Hydroxypropyl-β- — —— — — — 3 cyclodextrin (lb) Barite (lb) 145.3 146 145.3 145.3 145.3145.3 145.3 BARABUF ™ pH buffer (lb) 0.2 0.25 0.15 0.25 0.15 0.15 0.15pH before hot rolling w Shale 9 9.47 9.2 9.2 9.2 9.2 9.2 pH after hotrolling w Shale 9.83 9.3 9 9.4 9.6 9.4 9.6 % Shale Recovery 33 86.2 72.484.2 84 88.4 88

In addition, the Plastic Viscosity (PV) Yield Point (YP) Yield Stress(Tau zero) and Low Shear Yield Point (LSYP) of the invert (w/o) emulsiondrilling fluids were determined according to techniques well known inthe art using a direct-indicating FANN 35™ rheometer powered by anelectric motor. These results for the above formulations are alsoprovided in Table 3.

More particularly, the rheometer consists of two concentric cylinders,the inner cylinder called as the bob while the outer cylinder is calledas the rotor sleeve. The drilling fluid sample was placed in athermostatically controlled cup and the temperature of the fluid wasadjusted to 120±2° F. The drilling fluid in the thermostaticallycontrolled cup was then placed in the annular space between twoconcentric cylinders of the rheometer. The outer cylinder or rotorsleeve was driven at a constant rotational velocity. The rotation of therotor sleeve in the fluid produces a torque on the inner cylinder orbob. A torsion spring restrains the movement of the bob, and a dialattached to the bob indicates displacement of the bob. The dial readingswere measured at different rotor sleeve speeds of 3, 6, 100, 200, 300and 600 rpm. The dial readings are shown in Table 3.

Plastic Viscosity (PV) is obtained from the Bingham-Plastic rheologicalmodel and represents the viscosity of a fluid when extrapolated toinfinite shear rate. The PV is obtained from the 600 rpm and the 300 rpmdial readings as given below in Equation 1.

PV=(600 rpm dial reading)−(300 rpm dial reading)  (Equation 1)

Yield point (YP) is defined as the value obtained from theBingham-Plastic rheological model when extrapolated to a shear rate ofzero. It may be calculated using 300 revolutions per minute (rpm) and600 rpm dial readings on a standard oilfield rheometer.

Similarly, yield stress (Tau zero) is the stress that must be applied toa material to make it begin to flow (or yield) and may commonly becalculated from rheometer dial readings measured at rates of 3, 6, 100,200, 300 and 600 rpm. The extrapolation in this case may be performed byapplying a least-squares fit or curve fit to the Herchel-Bulkleyrheological model.

A more convenient means of estimating the yield stress is by calculatingthe Low-Shear Yield Point (LSYP) by the same formula shown below inEquation 2 though with the 6 rpm and 3 rpm dial readings substituted forthe 600 rpm and 300 rpm dial readings, respectively.

YP=(300 rpm dial reading)−PV  (Equation 2)

A low PV may indicate that a fluid is capable of being used in rapiddrilling because, among other things, the fluid has low viscosity uponexiting the drill bit and has an increased flow rate. A high PV may becaused by a viscous base fluid, excess colloidal solids, or both.

Gel strengths were measured at 10 seconds as follows. The drilling fluidsample is stirred for 10 seconds at 600 revolutions per minute (rpm) ona FANN 35™ rheometer. The drilling fluid sample is allowed to standundisturbed for 10 seconds. The hand wheel was slowly and steadilyturned in the appropriate direction to produce a positive dial reading.For instruments having a 3 rpm speed, the maximum reading attained afterstarting rotation at 3 rpm is the 10-s gel strength. The 10-s gelstrength in pounds per 100 square feet (lb/100 sq ft) was recorded. The10-second gel strength is considered the initial gel strength of thefluid.

Gel strengths were also measured at 10 minutes as follows. The drillingfluid sample is again re-stirred at 600 rpm for 10 seconds and then thefluid was allowed to stand undisturbed for 10 minutes. The hand wheelwas slowly and steadily turned in the appropriate direction to produce apositive dial reading. The maximum reading attained after startingrotation at 3 rpm is the 10-min gel strength. The 10-s gel strength inpounds per 100 square feet (lb/100 sq ft) was recorded.

More particularly, each of these tests were conducted in accordance withstandard procedures set forth in Recommended Practice 13B-2, RecommendedPractice for Field Testing of Oil-based Drilling Fluids, Fourth Edition,American Petroleum Institute, Mar. 1, 2005, the contents of which ishereby incorporated herein by reference.

TABLE 3 Drilling Fluid Rheological Properties Drilling Fluid Base 1 2 34 5 6 600 rpm dial reading 51 49 81 62 63 59 65 300 rpm dial reading 3836 56 45 47 43 50 200 rpm dial reading 29 30 47 39 42 35 42 100 rpm dialreading 15 21 35 28 31 26 30 6 rpm dial reading 4 5 10 6 7 7 7 3 rpmdial reading 3 4 8 4 5 4 6 Plastic Viscosity 13 13 25 17 16 16 15 YieldPoint 25 23 31 28 31 27 35 10 sec Gel Strength 3 4 9 5 6 5 6 (lb/100 sqft) 10 min Gel Strength 3 3 10 4 5 4 5 (lb/100 sq ft)

A thermogravimetric analysis (“TGA”) was performed to obtain thermalstability of β-cyclodextrin. TGA of β-cyclodextrin shows that itexhibits thermal stability up to 572° F. (300° C.) after which it beginsto degrade. Such a high thermal stability of β-cyclodextrin shows thatit can be used in high-temperature, high-pressure (“HTHP”) conditions inwater based fluids.

Cyclodextrins are commonly used as additives in food and pharmaceuticalindustries. Cyclodextrins have a National Fire Protection Rating(“NFPA”) health, flammability, and instability/reactivity ratings of 1,1, 0, respectively. Beta-cyclodextrin is readily biodegradable with 82%biodegradability in 28 days according to Zahn/Wellens EMPA test forinherent biodegradability, which was adopted as the OECD 302B test. Theacute oral/dermal LD 50 toxicity values were greater than 2000 mg/kg forrat when subjected to sample exposure. Beta cyclodextrin when subjectedto eco toxicity studies exhibited a 96-hr LC₅₀ of 7561 mg/l to Cyprinuscarpio (common carp). For the tests involving Daphnia magna, betacyclodextrin exhibited a 48-hr EC₅₀ of >100 mg/L. Beta cyclodextrinexhibited a 72-hr density EC₅₀ of greater than 100 mg/L to desmodesmussubspicatus (a common freshwater green algae) Source:http://www.cyclodextrin.org/CDPDF/safety/cavamaxw7food.pdf.

CONCLUSION

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein.

The exemplary well fluids disclosed herein may directly or indirectlyaffect one or more components or pieces of equipment associated with thepreparation, delivery, recapture, recycling, reuse, or disposal of thedisclosed well fluids. For example, the disclosed well fluids maydirectly or indirectly affect one or more mixers, related mixingequipment, mud pits, storage facilities or units, fluid separators, heatexchangers, sensors, gauges, pumps, compressors, and the like usedgenerate, store, monitor, regulate, or recondition the exemplary wellfluids. The disclosed well fluids may also directly or indirectly affectany transport or delivery equipment used to convey the well fluids to awell site or downhole such as, for example, any transport vessels,conduits, pipelines, trucks, tubulars, or pipes used to fluidically movethe well fluids from one location to another, any pumps, compressors, ormotors (e.g., topside or downhole) used to drive the well fluids intomotion, any valves or related joints used to regulate the pressure orflow rate of the well fluids, and any sensors (i.e., pressure andtemperature) gauges, or combinations thereof, and the like. Thedisclosed well fluids may also directly or indirectly affect the variousdownhole equipment and tools that may come into contact with thechemicals/fluids such as, but not limited to, drill string, coiledtubing, drill pipe, drill collars, mud motors, downhole motors or pumps,floats, MWD/LWD tools and related telemetry equipment, drill bits(including roller cone, PDC, natural diamond, hole openers, reamers, andcoring bits) sensors or distributed sensors, downhole heat exchangers,valves and corresponding actuation devices, tool seals, packers andother wellbore isolation devices or components, and the like.

The particular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. It is, therefore, evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention.

The various elements or steps according to the disclosed elements orsteps can be combined advantageously or practiced together in variouscombinations or sub-combinations of elements or sequences of steps toincrease the efficiency and benefits that can be obtained from theinvention.

The invention illustratively disclosed herein suitably may be practicedin the absence of any element or step that is not specifically disclosedor claimed.

Furthermore, no limitations are intended to the details of composition,design, or steps herein shown, other than as described in the claims.

What is claimed is:
 1. A well fluid comprising: (i) a continuous waterphase; (ii) a viscosity-increasing agent, wherein theviscosity-increasing agent comprises water-soluble hydrophilic polymer;(iii) a fluid loss control agent; and (iv) a cyclodextrin-basedcompound.
 2. The well fluid according to claim 1, wherein thecyclodextrin-based compound does not interact with theviscosity-increasing agent to increase or decrease the viscosity of thewater-based drilling fluid by more than 10 cP.
 3. The well fluidaccording to claim 1, wherein the water-based drilling fluid has lessthan a sufficient concentration of a viscoelastic surfactant or ahydrophobically-modified hydrophilic polymer to increase the viscosityof the water-based drilling fluid by more than 10 cP.
 4. The well fluidaccording to claim 1, wherein the water-based drilling fluid isessentially free of a viscoelastic surfactant and essentially free of ahydrophobically-modified hydrophilic polymer.
 5. A method of drilling azone of a well, the method comprising the steps of: (A) introducing awater-based drilling fluid into the zone, the water-based drilling fluidcomprising: (i) a continuous water phase; (ii) a viscosity-increasingagent, wherein the viscosity-increasing agent comprises a water-solublehydrophilic polymer; (iii) a fluid-loss control agent; and (iv) acyclodextrin-based compound; and (B) drilling in the zone.
 6. The methodaccording to claim 5, wherein the cyclodextrin-based compound does notinteract with the viscosity-increasing agent to increase or decrease theviscosity of the water-based drilling fluid by more than 10 cP.
 7. Themethod according to claim 5, wherein the water-based drilling fluid hasless than a sufficient concentration of a viscoelastic surfactant or ahydrophobically-modified hydrophilic polymer to increase the viscosityof the water-based drilling fluid by more than 10 cP.
 8. The methodaccording to claim 5, wherein the water-based drilling fluid isessentially free of a viscoelastic surfactant and essentially free of ahydrophobically-modified hydrophilic polymer.
 9. The method according toclaim 5, wherein the continuous water phase comprises a source of waterselected from the group consisting of freshwater, seawater, brine, orany combination thereof.
 10. The method according to claim 5, whereinthe treatment fluid additionally comprises a weighting agent.
 11. Themethod according to claim 5, wherein the weighting agent is in at leasta sufficient concentration such that the continuous water phase has adensity of at least 9 ppg.
 12. The method according to claim 5, whereinthe weighting agent comprises a water-soluble inorganic salt.
 13. Themethod according to claim 5, wherein the weighting agent comprisesbarium sulfate.
 14. The method according to claim 5, wherein theweighting agent is a solid particulate selected from the groupconsisting of: hematite, calcium carbonate, and any combination thereof.15. The method according to claim 5, wherein the weighting agent is asolid particulate having a particle size distribution anywhere in therange of 400 US mesh to 100 US mesh.
 16. The method according to claim5, wherein the water-based drilling fluid includes less than 10% of anycombination of dissolved alkali metal halide salts by weight of thewater.
 17. The method according to claim 5, wherein theviscosity-increasing agent comprises a water-soluble hydrophilicpolymer.
 18. The method according to claim 17, wherein theviscosity-increasing agent comprises a cellulosic polymer, a polyacrylicpolymer, or natural gum polymer.
 19. The method according to claim 5,wherein the fluid-loss control agent is selected from the groupconsisting of: bentonite particulate, an organic colloidal-sized solidparticulate; a filter cake bridging material, a lost-circulationparticulate, and any combination thereof.
 20. The method according toclaim 5, wherein the fluid-loss control agent is a particulate selectedfrom the group consisting of bentonite, a biopolymer, cellulose polymer,modified cellulose, starch, modified starch, polyanionic cellulose,plant tannin, a polyphosphate, a lignitic material, a lignosulfonate, asynthetic polymer, calcium carbonate, asphalt, gilsonite, walnut shells,and mica.
 21. The method according to claim 5, wherein the fluid-losscontrol agent is selected from the group consisting of polyanioniccellulose, modified starch, and any combination thereof in anyproportion.
 22. The method according to claim 5, wherein the fluid-losscontrol agent is in a concentration of at least 1 ppg of the continuouswater phase.
 23. The method according to claim 5, wherein thecyclodextrin-based compound is a cyclodextrin.
 24. The method accordingto claim 5, additionally comprising the step of: forming or providingthe water-based fluid.
 25. The method according to claim 5, wherein thezone penetrates or is in a subterranean formation of shale.
 26. Themethod according to claim 5, wherein the cyclodextrin-based compoundstabilizes a shale formation.